Community and Landowner Renewable Energy Loan Study

Annex 1 The Renewable Energy Market for Communities and Landowners in Scotland

3.1 Introduction

3.1.1 It is widely acknowledged that, in both UK and EU contexts, Scotland is particularly well endowed with renewable energy sources. It has a long coastline, with significant potential for electricity generation from tidal streams; it has an estimated 1,200 MW of untapped hydro energy potential, spread across the country, but generally concentrated at the small-medium scale and in upland areas; it has the largest onshore, and one of the largest offshore, wind resources in the world - equivalent to 25% of the total wind potential of Europe; and a large and well developed forestry sector, which is already providing in excess of 90% of Scotland's renewable heat - close to 1 TWh per annum.

3.1.2 The potential for other forms of renewable energy generation, particularly solar thermal, photovoltaic and heat pumps is less in Scotland than more southerly latitudes, but nonetheless has the potential to make a considerable contribution towards achieving renewable energy targets. Although for the most part, these particular technologies will be deployed at the individual household level. The performance characteristics of these technologies also impose limitations. Heat pumps, for example, are suited to properties which require a constant temperature, as they operate most efficiently when providing low grade heat, i.e. underfloor heating, which can take time to heat up and cool down. This makes them less suited to multi-purpose buildings such as community halls, which may be used for several events a day, and irregularly throughout a week.

3.1.3 The introduction of Feed-in-Tariffs ( FiTs), and the proposed introduction of the Renewable Heat Incentive ( RHI) are having, and will continue to have, a transformative effect on the economic viability of renewable energy technologies, although some are clearly proving more profitable than others. The overall profitability of any investment is directly related to two factors : in the case of electricity, the proportion of time that the installation is actually producing electricity, i.e. wind/water turbine is turning, PV cells are operating; and in the case of heat under the proposed RHI, the proportion of the time that there is a legitimate demand for heat from the renewable device.

3.1.4 It is clear from the research, assuming the implementation of the RHI goes ahead, that there will be very few rural communities or landowners who will not have at least one form of renewable energy technology that will be suited to their needs and circumstances. For communities and landowners to realise this potential to generate income or reduce their reliance on fossil fuels, the challenge now is how to overcome the few remaining barriers to investment in renewable energy technology. A Loan Fund could play a key role in removing the final financial barrier to progress, which in turn would greatly enhance the ability of communities and landowners to surmount the remaining non-financial barriers.

3.1.5 There follows a technology-by-technology assessment of the opportunities for communities and landowners to invest in renewable energy systems in Scotland.

3.2 Hydropower

The Context

3.2.1 The hydropower market in Scotland has seen something of a renaissance in recent years, after a long period of limited development since the large schemes constructed in the 1940s-60s. Installed capacity of hydropower in Scotland is now around 1,387 MW (excluding pumped storage). Much of this is comprised of the older storage-based schemes, and with the exception of the recent 100 MW Glendoe scheme, most new hydropower developments are smaller, between 500kW and 5 MW, and tend to be 'run-of river', that is without a large dam or reservoir. Most schemes have been developed in Dumfries and Galloway, Argyll and the Central and North Highland areas, where high rainfall combined with mountainous terrain and a lower population density have combined to create optimal conditions for hydropower development. Around 103 MW1 of hydropower generating capacity is under construction at present.

3.2.2 Historically, a significant number of schemes were developed by farmers and private estate owners in the 1900s, to power farms and estates before the national grid reached the more remote glens in the Highlands. Many estates are now looking again to hydropower, either reinstating disused schemes or developing new ones to feed into the national grid and provide stable, diversified and long-term income. Private ownership accounts for a considerable percentage of the new developments underway, and several estates have gone on to form companies to develop schemes in other areas after their own initial experiences.

3.2.3 Community hydropower schemes are also developing at a fast pace in Scotland. Four main schemes are operational (at Knoydart, on Eigg, at New Lanark, and at the Abernethy Trust Centre at Ardgour), with another scheme under construction at Blairgowrie. CES are also advising another c. 40 community groups who are in various stages of hydropower project development across the country. These groups have been supported through grants from HIE and the Scottish Government to take them through the early development stages.

3.2.4 Given the important climate change and energy security agendas, hydropower development has been well supported politically in Scotland in recent years, and because most run-of-river schemes have less visual impact than wind turbines, they have often been less controversial locally. However, the development period is still lengthy and risky, often with planning, grid and environmental issues involved. This means that there can be significant time and capital input required before a scheme receives all necessary consents.

3.2.5 A key limitation for community and landowner hydropower schemes in particular is the geographical constraints they will often face. Unlike wind turbines, which may have some flexibility in their siting, hydropower schemes normally need to be sited according to the local topography, catchment area and flow characteristics of the land and river on which they are based. Communities and landowners will only have a limited area in which they can develop schemes (either the land which they own, or the area in which they operate), so their choices of sites is likely to be restricted.

3.2.6 This has particular significance in terms of the requirements they may face from planning authorities and SEPA to consider alternative sites (or even alternative technologies); often this may not be possible. Another significant problem this can create is grid access; unfortunately the areas of greatest future hydropower potential (West Highlands and Argyll) are the areas with least grid capacity to accept new connections. If a connection requires long distances of new cabling, or wider reinforcement of the grid, this may make it economically unviable for the hydropower scheme to go ahead.

3.2.7 Because of site limitations, many of the most suitable locations will have already been developed, which may restrict options for communities or landowners. However, relatively small changes in policy, energy prices or grid availability could mean that some sites which were once unsuited for development could become viable.

3.2.8 A significant barrier to micro hydropower development (below 50kW) at present is the lack of MCS-certified installers based or operating in Scotland (only one based in Scotland and four in the rest of the UK). There are other hydropower installers with good track records on installation; however, there has been reluctance by them to participate in the MCS accreditation process. To be eligible for a grant or the Feed-in Tariff, hydropower schemes below 50kW must be installed by an MCS accredited installer - having so few available is a major bottleneck.

3.2.9 Cost can be another barrier for those looking to develop a hydropower scheme, as the installation costs per kW tend to be higher than those for wind, particularly as many of the more economical sites have already been developed. Crossing features like railways or roads can add very significantly to the cost of any installation. These costs can, however, be mitigated by the higher load factor many hydropower schemes will work to compared to wind, and by the longer lifespan hydropower schemes tend to have. But, if the initial capital cannot be raised (or the scheme will not pay back within a given loan period), then the capital outlay may be prohibitive.

The Outlook

3.2.10 The Feed-in Tariff has significantly improved the viability of many potential small and micro hydropower schemes. Some concern has been expressed that too few bands were proposed, which again may lead to gaming, with schemes being sized just below the 2 MW and 100kW bands because of the significant increases in tariff levels below these bands. Others feel that the 15-100kW band tariff is not sufficiently generous to make many schemes below 50kW viable, but generally, FiTs will massively improve prospects for many schemes. FiTs have helped reduce the impact of variability in power price, and because they are government-backed, debt financing should be more readily available for developers.

3.2.11 The 2008 Scottish Hydro Power Resource Study identified 657 MW of financially viable hydropower resource, spread over around 1,000 schemes which could be theoretically be developed; when the software was run again more recently taking into account the Feed-in Tariff, this rose to over 7,000 schemes, and 1,200 MW, clearly demonstrating the positive effect the FiT could have (and potentially leading to between 300 and 1,400 new jobs). This also shows how many of those schemes could be below 500kW (the mean size would be around 170kW), which is very much in the bracket of the size of scheme typically developed by communities and landowners. However, these figures are very sensitive to any changes in the discount rate applied to cashflows.

3.2.12 The study also noted that the available resource would be halved if the current grid constraints are taken into account. Without urgent investment in the grid, especially in the Western Isles, West Highlands and Argyll, hydropower development will be stifled.

3.2.13 The sector also has to operate within stated Scottish Government policy to optimise the development of micro-hydro to minimise environmental impact - hence the new draft SEPA guidance for developers of run-of-river hydropower schemes which is designed to help develop sites appropriately.. This could affect landowners and communities, who may not always be able to consider alternative sites or technologies.

3.2.14 Micro-hydro in particular may present opportunities for on-site use of energy. For example, the scheme at the Abernethy Trust in Ardgour can export surplus to the grid - but it is planned to use much of the output to heat and power the buildings on site. This leads to double benefits economically, because FiT income is still received, and costs for purchasing imported electricity are avoided. It also helps reduce the impact on the local distribution network because less power is being exported from the site. This technique has been employed at a macro-scale at several large aluminium smelters in the Highlands, and there is potential for similar industrial or business links in the future (for instance powering 'green' data centres or other energy-intensive businesses).

3.2.15 The community projects taken forward to date (and the ones currently in development) have been largely supported through grant. In order to enable new projects to be developed, and for existing projects to keep developing to the planning submission stage, there is a strong need for either the continuation of grant support, or the provision of low interest loans to cover the significant development costs involved. Without this, and given the challenges noted previously, and uniformly scarce financial resources, the risks and costs involved in taking a project forward would be too great for most small community groups and businesses to realistically bear. This may apply even in micro-hydro schemes, which often still have to go through planning and regulatory processes before consent.

3.3.1 Scotland as a country has an unrivalled raw wind resource within Europe. This, when combined with having a large, relatively sparsely populated landmass, has led to rapid growth in the macro-scale onshore wind market over the past decade. Scotland now has an operational installed capacity of around 2,165 MW - greater than that of hydropower generation in Scotland - has a further 2,847 MW consented for development and at least another 4,368 MW of capacity in planning or appeal. There are a wide range of sizes of wind developments and technologies operational, with windfarms ranging from one turbine to 140, and most turbines between 800kW and 2.5 MW. Their geographical spread extends over much of Scotland, with more limited development in Shetland due to grid constraints, and limited development in the National Parks, West Highlands and Central Highlands, mainly due to cost, grid and MOD constraints, and landscape issues.

3.3.2 There are four large wholly-owned community developments already operational in Scotland (Gigha, Findhorn, Westray and Tiree), with a number of others at an advanced stage in the Western Isles, Orkney and Aberdeenshire. There are 135 other community groups at different pre-capital stages throughout the country. 67% of these groups are wind from 24kW to 9 MW in size. 18 of these wind projects have planning consent and a further 8 have a firm grid connection offer and are at the stage of working towards construction. A number collaborative or joint venture projects have been formed between communities and landowners, most notably Fintry, Ardrishaig and Neilston. There are also several local share offer schemes where local individuals have formed cooperatives to buy in private windfarms such as at the Millennium Windfarm and Boyndie Airfield. These cooperative schemes have been facilitated by Energy4All.

3.3.3 Success to date for wholly-owned community schemes has been heavily dependent on significant grant support through SG and HIE during pre-capital stages in particular, and from Big Lottery and social lenders during later phases. CES has also provided independent technical advice and support to these groups. Communities like Fintry have achieved their aims without state support through negotiating mortgage agreements with a private developer, but this is only possible in large developments and the group do not own a physical asset, only rights to a share of the PPA from the scheme. So far, very few private developers have shown a willingness to enter into the more novel arrangements illustrated at Fintry and the Energy4All sites (which were led by the same developer). Energy4All also supports the development of projects wholly owned by investment cooperatives, although none have yet been finalised in Scotland. In return for helping to establish these, it requires a development fee based on a percentage of the project's capital cost. Recently, E4All opened a share offer for a new UK fund ('Energy Prospects'), which will invest in the pre-planning development costs of local wind coops in return for a fee. People investing in the fund will spread their risk as the fund will invest a range of projects.

3.3.4 Private landowners in Scotland have taken forward small but significant numbers of 1-3 turbine developments, particularly in Aberdeenshire and Angus, but also in the Central Belt and Orkney. The majority of these schemes have been exporting electricity to the grid.

3.3.5 Political support for wind development has been strong in Scotland to date, which has benefited growth in the industry. The good wind resource across much of the country means developments in the right locations are often an attractive proposition. However community groups and landowners are by their nature confined to their own locale, so those in areas with a poor wind resource have not been able to benefit from wind energy schemes.

3.3.6 Although community developments tend to be relatively small and are often well-supported locally, there can still be problems from objectors and nimbyism. A key way to reduce this has been to ensure the scheme has genuine and locally-determined community benefits arising from it, and to make sure the scheme is well-sited, with visual and environmental impacts minimised. This requires good independent advice and early communication with statutory consultees (as well as the local community), but it will often also require specialist consultancy work. This further increases the risk capital required from the community or landowner.

3.3.7 The micro-wind industry (<50kW turbines) is also very strong, with two manufacturers of micro-turbines based and manufacturing in Scotland (Proven and Renewable Devices), a third (Gaia) with their headquarters in Glasgow, and a final manufacturer with their UK dealership, installation and maintenance headquarters in Orkney (Eoltec). There is also a wide network of installers for other turbines (largely manufactured elsewhere in the UK). The latest official figures in 2008 indicated that 410 out of the c. 2,500 UK micro-wind installations were installed in Scotland, but although more recent figures are not held centrally, there has clearly been a step change in interest, planning applications and actual installations across Scotland over the last two years, meaning this figure will need to be dramatically revised.

3.3.8 Overall, 75% of the UK market is supplied by UK-manufactured turbines, and 59% of output from UK manufacturers is exported overseas, accounting for a significant percentage of global sales. However, many communities, businesses and individuals seeking planning permission for micro-wind systems find that practice varies - in part owing to the Scotland's geographical diversity. While planning authorities are best placed to consider potential environmental impacts across a range of criteria locally, inconsistency can cause barriers to good projects. The Scottish Government is updating its planning advice to provide guidance to upskill planning officers and local authorities in this important field. It is also consulting on permitted development rights for non-domestic microgeneration as required by the Climate Change (Scotland) Act 2009 that would benefit the sector.

The Outlook

3.3.9 Although there is a good Scottish and UK manufacturing base for turbines up to 20kW, beyond this there is a very significant (global) gap in the market for turbines up to 500kW. Within this very large range, there are only seven models of turbine available (the Endurance 50kW, WES 80kW, Northwind 100kW, Vestas/ ACSA 225kW, WES250kW, Enercon 330kW, and Windflow 500kW). Only a handful of these machines have been installed so far in Scotland, the result being that the turbines which are available have yet to be tested in the more demanding Scottish wind regimes. Although this gap in the market will hinder wind energy development, it presents an excellent opportunity for Scottish manufacturing if a company were able to start developing turbines of this size. This would allow Scottish industry to develop, having missed out in early turbine development in the 1980s and 90s to Denmark and Germany.

3.3.10 Turbines of 800kW - 3 MW have been installed in the Scottish environment and are now relatively easy to procure. Enercon, a major German manufacturer, are happy to deal with single turbine sites or small clusters, and offer local service bases and bankable performance guarantees. Encouraging competition would be beneficial.

3.3.11 A major issue for further wind development in Scotland is likely to be physical space for development. There is a growing consensus that all the large, 'easy' and less controversial sites have now been taken (either with options signed, planning consented or the development installed), so it will become more challenging to find potential sites. Cumulative visual impact is becoming more of an issue in planning applications, and is not yet well understood by all developers (and not necessarily well defined by planning authorities). This means that it will be much more risky for developers of all sizes and types to develop projects on these 'borderline' sites, given the enhanced risk that they might not receive planning consent and they will have to take even more care to site appropriately. This could lead to a slowdown in the development of the wind sector in Scotland, with consequences for jobs and renewables targets. With so many commercial developers now seeking sites there is a clear window of opportunity in which the non-profit and farming sectors must maximise their opportunities.

3.3.12 Given that the larger sites have mostly been developed or are in planning, there are most likely to be opportunities for smaller developments, particularly sub-3 MW/3 turbine sites which could fall below the threshold for an EIA. Developments of this size fall within typical community or landowner schemes, and are likely to have less visual impact. Developments under 1.5 MW are well supported by the Feed-in Tariff, meaning they might once have been uneconomical but could now be viable to develop. Developers now need a stable support regime, so they can accurately forecast returns and invest in the right projects.

3.3.13 Whilst a stable FiT regime will reduce risk, it does will not eliminate it; developers are operating in a sector which regularly faces 'showstoppers' in the form of grid, planning and environmental hurdles which have to be overcome. These issues cannot always be identified until a considerable amount of time and money has been invested, and can easily halt a project. This means significant risk is unavoidable. Community projects have previously benefited from grant support to take them through these early, high-risk phases. If this support ends, it is unlikely many groups could afford to take such risks, as most have very little in terms of their own reserves, especially the groups who stand to benefit most from wind energy revenues. Finding the finance for the pre-capital stages from commercial lenders has not been a viable option.

3.3.14 Owing to the risks involved, loans are rarely used for this stage, and most new start commercial developers depend on equity sources. For community renewable energy projects to continue to flourish, some form of financial support from the Scottish Government is essential. If public budgets allowed, grant support at the pre-feasibility stage would maximise the number of groups developing projects, and would improve the quality of projects coming forward. Soft loans or quasi equity investments with a repayment dependent on future profits would allow a long term return to the Scottish Government.

3.3.15 Some grant support may be available to communities through the Big Lottery Fund, but the availability of grant from this source is likely to be diminished as more and more groups apply to fewer available grant schemes. If grant or risk-free finance is not available in the short term, then many community projects which are already part-way through the development stages will be unable to continue.

3.3.16 For landowners, many of the same issues apply, although if a grant or loan scheme was opened up to landowners as well, there would be an issue around who was eligible to access this support. It would often be difficult to differentiate between private and corporate developers, given the mix of different ownership arrangements available now. Some wind developments might be wholly owned by a landowner; other landowners might only receive an annual rent for ground leased by a private developer; and often schemes are now developed as a joint venture between private companies and landowners . If the aim of the fund was to generate significant social benefits to rural communities (as well as increasing renewable electricity generation), then access to the fund would have to be based on the developer showing genuine wider community gains from the scheme, beyond the community benefit payments which are now considered standard. Work has shown much greater benefits for locally owned wind projects than large developers. The revenue generated gives the equivalent of 1.47 jobs vs 0.23 jobs/0.8 MW turbine, giving a larger local economic benefits.

3.3.17 Microgeneration projects tend to require less pre-capital investment, and most of those in suitable locations should be viable using FiT income alone, without grant support. However, finance would still be necessary to cover the installation costs, and this is still likely to be considered risky by small organisations unused to taking on loans. This is especially the case for community groups planning to install turbines which often do not yet have a 10-year performance record to match the likely repayment period for a loan. If capital grants remained available to cover part of these costs, it would help reduce this risk and would reduce the payback period, meaning groups would earn more through FiT income to reinvest in their community. An element of capital grant, linked to a soft or reduced risk loan, and operating within de minimis limits, would substantially increase the uptake of micro-renewables in Scotland. This offers a significant opportunity for small-scale income generation, but without support for the upfront costs, many non-profit organisations and SMEs will be unable to take advantage of the potential.

3.3.18 Procurement of wind turbines has been another issue for some community projects in the past; many manufacturers have been unwilling to send single turbines to remote sites because of the logistical implications for both installation and long-term maintenance. Although this has been a challenge to overcome for many projects, it also represents an opportunity for Scottish industry, as hopefully the FiT incentives for smaller schemes like this will encourage companies to consider supplying and maintaining turbines at remote sites.

3.3.19 Grid connections have proved a major delay to many community projects, particularly in Argyll and the Northern and Western Isles. In some cases, these will only be resolved through major infrastructure investments, such as the Western Isles and Shetland Interconnectors, but other measures could help many projects to go ahead. In areas with inadequate grid infrastructure, the cost of upgrading the grid to accept generation can be prohibitively expensive.

3.3.20 Additionally, some projects have been blocked because grid capacity has been allocated to developers making speculative connection requests for projects which do not have planning consent, and are taking up grid capacity which could be used others. Connect and Manage is likely to allow some smaller projects to progress by constraining other generators elsewhere on the grid at key times of peak output, and this has been welcomed.

3.3.21 Transmission charges remain very costly for Scottish projects, particularly those in weaker parts of the grid, and review of this would allow for a much more equitable system, this could improve the viability of some schemes.

3.3.22 In some particularly grid-constrained areas, innovative solutions have been developed to overcome some of these issues. Wind2heat started in Shetland as an off-grid system of microgeneration, where small turbines directly powered storage heaters for community buildings. Communities in Shetland and the Western Isles unable to connect their MW-scale projects into the grid are also developing wind-based district heating systems, which would still generate FiTs to reinvest in community projects and help to reduce both fuel poverty and fossil fuel use.

3.4.1 The solar market has, until recently, been very limited in Scotland, particularly for PV, which has suffered from high capital costs, a limited installer network and relatively low subsidies through ROCs. Grant-aided solar thermal has had more widespread use, particularly in domestic locations and in larger arrays for major heat users such as swimming pools. However it still accounts for only 4% of installed renewable heat capacity in Scotland, and produces only around 0.8% of annual renewable heat output in Scotland (equating to 0.00011% of total Scottish heat demand) according to the Sustainable Development Commission Scotland 1. This contrasts sharply with the meaningful amount of energy solar thermal can produce on individual scales; an average-sized array in Scotland can provide 40-50% of the annual hot water requirements for a family home, and up to 100% of summer requirements 2.

3.4.2 Likewise, there is currently only around 32 MW of PV capacity installed in the entire UK3, despite the fact that PV output can be easily calculated and predicted, panels easily (and unobtrusively) installed, and systems run over 30 years or more with little to no maintenance. A well-sized system could provide 30-40% of the requirements of an average home 2. Again, the main limiting factor to widespread adoption has been capital cost.

3.4.3 The demand points for heat in Scotland are split evenly between domestic space heating and hot water, which accounts for around 50%, and commercial and industrial heat. Of the commercial and industrial heat, half is used in industrial process, with the remainder providing hot water and space heating in industrial and commercial premises 1. It is not known what the existing split is between use of solar thermal in domestic buildings and its use in community, business or industrial buildings. Many domestic and community installations will have been made possible through grant funding, to which the private sector by and large will have not had access. If the proposed Renewable Heating Incentive 4 becomes a reality, there will be incentive for all those with summer hot water demands to consider solar thermal.3.4.4 On-site demand is likely to be the largest determining factor for selecting either solar PV or solar thermal. Whilst electricity produced by PV panels can be readily exported to the grid in most areas, the low export tariff of around 3p/kWh incentivises use of this power on site. This means it will be most beneficial to individuals, community groups or businesses with a high summer daytime electrical demand, as this is the time at which PV will produce most output. For solar thermal, on-site use is even more critical, as unless feeding into an existing district heating scheme, heat cannot readily be exported. Again, it will suit buildings with a summer hot water demand, and although energy production will be during daylight hours, heat storage is achievable through the use of accumulator tanks.

3.4.5 Good opportunities solar thermal to reduce the reliance on other forms of heating exist in commercial operations such as catering, hotels, leisure centres, hospitals, and care homes. A south-east to south-west facing roof is important for any solar installation, and proposed and existing Permitted Development Rights for panels should aid adoption of the technology. PV could be located in almost any suitable location with a grid connection, but again will be most economically advantageous for those with high summer daytime demand, which is likely to cover a wide spectrum of sectors.

The Outlook

3.4.6 At present, the solar thermal industry in Scotland (and the wider renewable heat industry) is in a period of considerable uncertainty, following the closure of CARES to new applications this financial year and the final closure of other major grant schemes like Low Carbon Buildings Phase 2, and the Scottish Householder Grant Scheme. Future work for the installers and solar manufacturers is very much reliant on the proposed RHI (which has still not been confirmed by the UK Government), or on a re-starting of UK or Scottish Government grant schemes. Without these support mechanisms, solar thermal installations will be restricted to a small number of sites where the technology is economically viable at present cost, or where cost is less important to the consumer than the environmental benefits. Certainty for consumers, manufacturers and installers is urgently required for growth in the sector to be sustained 5.

3.4.7 The proposed RHI would create a long-term environment for supporting growth of solar thermal systems, and would in some respects provide longer-term certainty for stakeholders (at least until the review periods where the RHI tariffs might be adjusted). However, to be successful amongst householders, small businesses and community groups in particular, it is essential that the RHI is matched by the availability of affordable finance to pay the up-front costs. Without this, there is little chance of solar thermal systems being affordable for many individuals and organisations. The Solar Trade Association has expressed concerns that the proposed RHI levels will only give a typical return on investment of around 6% 6. If this is the eventual outcome, then it is also essential that the loan repayment periods match the payback period for the solar thermal system.

3.4.8 It was hoped that the capital costs for both solar thermal and PV would fall once the FiT and RHI were brought in, and once economies of scale and competition increased. To some extent, this has been seen with a fall in price of PV panels, although this was partly related to the global price of silicon as a commodity, which has begun to rise again in recent months 7. A wider and more competitive installer and manufacturer base in the UK would greatly benefit the affordability of solar systems.

3.4.9 Solar PV in Scotland (and the rest of the UK) appears to be entering a phase of rapid expansion following the announcement of the Feed-in Tariff. Different opportunities are arising for 'free' solar panels for domestic and commercial properties of all sizes, with the developer taking the FiT revenue for the 25 year period, and the householder or host business receiving free energy for the panels.

3.4.10 The fall in the average price of PV panels, and the FiT rates for solar PV are now allowing rates of return of up to 12% on investment, so many with suitable buildings are keen to own the systems themselves. In some of the sunnier parts of the UK, farmers with large roof spaces on barns and other buildings are starting to look at the income opportunities PV can provide over the long term 8. Again, the ready availability of finance will be crucial to ensuring success, particularly for community organisations which may not have established credit histories.

3.4.11 There are some barriers to widespread adoption of solar thermal and PV; the consultation on Permitted Development Rights is welcomed, but many of the caveats proposed may unwittingly rule out large urban areas from PD rights because they are within 3km of an airport or helipad. This could make it far harder for many businesses and organisations in urban areas (or indeed entire islands, such as Colonsay) to install solar arrays.

3.4.12 Most solar installations will not require significant pre-development investment, although some larger schemes might require design or feasibility studies initially. The cost of these is not perceived to be a major barrier at present, although the provision of high-quality and independent advice to consumers would ensure that the majority of installations are robust, well-sited and meet the expectations of the householder, business or community.

3.4.13 There are very significant opportunities for the development of solar thermal in the future; although not a technology which will provide all the hot water needs of a building all year round, it could play an important part in reducing energy consumption in Scotland. The Solar Trade Association have reported year-on-year growth of more than 50% for the industry, which they expect to continue for the next decade, and predict that by 2020 they will be installing over a million domestic systems each year 9.

3.5.1 According to government sources 1, the total Scottish heat market is slightly more than 60 TWh per annum, the vast majority (>98%) of which is provided from non-renewable sources. Of the 0.845 TWh of heat which is provided from renewable sources, the majority of this comes from the direct combustion of biomass - around 83% of the total renewable heat in Scotland.

3.5.2 The demand points for heat in Scotland are split evenly between domestic space heating and hot water, which accounts for around 50%, and commercial and industrial heat. Of the commercial and industrial heat, half is used in industrial process, with the remainder providing hot water and space heating in industrial and commercial premises 1.

3.5.3 The industrial process heat component is a significant component in the makeup of the renewable heating figures for Scotland, with the timber processing industries particularly dominant. Their use of wood co-products for process energy accounts for over 62% of the total renewable heat 2. Economies of scale, the opportunities for waste wood disposal, and familiarity with technology and materials handling issues makes using wood for heat energy a straightforward decision for the timber processing industry.

3.5.4 Alongside the large-scale use of biomass for process heat, the medium to small scale biomass heating market has been growing slowly but steadily in Scotland since about 2003. Installations have typically included public buildings, such as schools, hospitals and visitor centres, alongside private sector schemes, the most common being farm steading conversions, rural business parks and traditional estates/country houses. Some third-sector schemes have also gone forward, including a small number of district heating schemes for social housing projects.

3.5.5 Research for Forestry Commission Scotland 3 indicated that, in 2009, there was a net increase of 16 installations at the small-medium scale, taking the total number of commercial and industrial heat-only biomass systems to 155. This data indicates a mean plant size of 175kW and an average fuel use of 122 odt/yr.

3.5.6 Installations at the domestic level will also have increased over the last decade, but data for this market segment is not readily available. The SDC report, Renewable Heat in Scotland 1, explored the complexities of this issue, concluding that "both the energy and capacity figures for micro-scale biomass involve very significant uncertainties". For this and other reasons, primarily relating to the straightforwardness of the technology and comparatively low capital cost, individual domestic installations are not addressed in this research.

The Outlook

3.5.7 The dominant factor for the biomass heating industry in Scotland at the present moment is the proposed Renewable Heat Incentive ( RHI). All parts of the sector, from the forest industry through to installers, maintenance contractors and consultants, are eagerly anticipating the introduction of the scheme and the transformative effect it will have on the industry.

3.5.8 Whilst the introduction of the RHI is by no means certain, and in its final form is unlikely to see tariff levels as generous as those put forward in the consultation document 4, it has the potential to end the boom-and-bust cycle of grant aid that has characterised support for the sector to date. Whilst schemes such as SBSS, SBHS and CARES have played a valuable role in supporting biomass heat installations to date, and the support available has met industry capacity,a move to a guaranteed payment system such as the RHI will provide much-needed certainty for the industry, as well as improving project economics and increasing market demand.

3.5.9 Various attempts have been made to quantify the potential market demand for biomass heating in Scotland, which in the early days for the industry were driven more by the opportunity it was felt to offer for the forest industries than by the need to understand the technology's ability to meet CO 2 reduction targets. The earliest meaningful report was produced for Scottish Enterprise by Econergy Ltd., a leading UK biomass boiler installer, and set out a range of possible market growth scenarios.

3.5.10 Broken down into domestic and commercial/industrial sectors, the Econergy report identified a total domestic market potential of around 5 GWh of heat across c. 530,000 off-gas households - the most logical and cost-effective starting point for market development in the pre- RHI world. For the commercial/industrial sector, again off-gas, the report identified around 23 GWh of market potential spread across around 11,700 premises. Bringing gas grid connected sites into the equation increases the market potential hugely - well beyond the capacity of the Scottish forest industry to serve it with fuel.

3.5.11 Assuming other barriers are removed or overcome through the continuation of support efforts such as the RBAN project, Carbon Trust Biomass Heat Accelerator and the like, there is no reason why small and medium scale biomass heating should not make up a significant part of Scotland's future renewable heat provision. As the Econergy report states as its number one 'headline issue', "the scale of the market opportunity is huge, and notwithstanding a number of genuine market barriers, is not limiting per se."

3.5.12 The more recent attempt by SDC to assess the future market potential for biomass heating concludes that "it is clear that there is very significant potential for a substantial increase in small to medium heat only biomass. Meeting a further 2-3% of heat from small to medium scale installations by 2020 seems feasible.". In reality, this would equate to between 1.2 and 1.8 TWh, or 670 and 1,000 medium sized leisure centres, or 86,000 to 128,000 average households. To take the slightly blunter tool of dividing the total number of terawatt hours by the mean boiler size and fuel use identified in the FCS research 3, this would equate to between 2,050 and 3,100 new, 175kW biomass boilers being installed between now and 2020, or 200 to 300 per year. Whilst this requires the year-on-year installation of roughly double the total current number installed in Scotland, the figure is reasonably realistic in light of the proposed RHI and the appetite of the industry for growth.

3.5.13 Given the likely wide range of schemes that will become profitable under the proposed RHI regime, the opportunities for landowners and communities will be many and varied. In the more mature biomass heat markets of Austria, Germany and Scandinavian countries, community and landowner ownership of individual boiler installations and of community district heating schemes is commonplace. Finland, for example, had around 300 biomass district heating plants in 2006, of which roughly a third were owned by community or landowner cooperatives.

3.5.14 Schemes which are coming forward to the feasibility phase in anticipation of the RHI include, for example, rural community enterprises focusing on contract drying, fish farming and covered horticulture, full ESCo offerings from the wealthier end of the farming/landowning spectrum, and cooperative ownership of boiler plant and other renewable energy technologies in public buildings, including a hospital. This trend, supplemented by community and landowner ownership of district heating systems, is likely to continue regardless, and will accelerate markedly should the RHI be introduced as planned.

3.6.1 The deployment of biomass CHP technology in Scotland, as in the UK more widely, has to date only been observed in large scale industrial applications, and even then on very few sites. Uptake has predominantly been in the wood processing industries in the UK, where the technology has long been used because of the obvious synergies between high heat demand and the presence of waste biomass.

3.6.2 It is considered unlikely that biomass CHP at a scale which is either economic, or suitable for the majority of landowners and communities to develop themselves, will be available any time soon. That said, a small number of biomass CHP plants are at the early development stage in various parts of the UK. These projects are high risk, and are utilising technology which is far from commercially ready.

3.6.3 Discussions with the programme manager for the UK's largest and longest running wood energy technology accelerator, who supported a range of CHP schemes through this programme, indicated that anyone who considers investing in small scale (sub-500kWe) biomass CHP should be prepared to be a guinea pig, have a great deal of time to invest in the technology and, most importantly, should have very large cash reserves. Similar responses have been received from discussions with many other professionals in the field, who remain confident in the ultimate success of the technology, but rarely speak positively of the readiness of small-scale CHP for commercial deployment at present.

3.6.4 The latest advice from the Forestry Commission's Biomass Energy Centre 1 ( BEC), the focal point for technical advice on biomass production and use in the UK, is that :

3.6.5 "Large scale (>2 MWe) biomass CHP usually uses conventional, steam turbine generating technology, but below this more exotic technology is required to achieve good efficiency. Many of these technologies are under active development and they cannot yet be expected to perform as commodity items. A biomass CHP installation should always be considered and specified in terms of the thermal output, not electrical. It is considerably easier to import or export an imbalance in electricity via the National Grid than to dissipate excess heat.

Heat generation will always accompany electricity generation and a suitable load will be required during all operation, including in summer. For this reason, an industrial application requiring process heat, or hotel or hospital is likely to be much more suitable than a purely domestic development. Small scale biomass electricity generation is a relatively low efficiency use for biomass, if the heat is not used profitably."

The Outlook

3.6.6 Whilst the degree of market penetration achieved by small scale biomass CHP in Scotland to date is virtually zero, the outlook for the next decade is actually very positive. Support mechanisms such as FIT's, ROC's and the proposed RHI, and increasing confidence in the technology, will mean that biomass CHP is likely to achieve significant market penetration in the medium and long term, particularly when linked to district heating systems. However, the types of organisations taking these sorts of projects forward are unlikely to be landowners or community groups, due to the very high capital costs and technical risk associated with this technology.

3.6.7 As the BEC information sheet notes, the most profitable locations for CHP plants are where there is a relative constant demand for the heat output from the plant, such as in an industrial process, hospital or (large) hotel. These sorts of applications are not typically accessible to the majority of communities or landowners, although there may be some schemes which come forward within the next 5 years.

3.6.8 Modelling undertaken by SAC for a community organisation 2, using CES funding, indicated that a small project based on a containerised Stirling DK 35kWe / 140kWth updraft gasifier unit, had a total project cost of around £300,000. Paybacks for the project ranged from 5 to 12 years, depending on the heat load and RHI payment levels. It was also noted, however, that although the total installed cost was only around £235,000, a further 20% should be allowed for contingencies, and that professional fees (especially insurances) would be around 10% to account for the technical and financial risks associated with the project. The community organisation has since opted to pursue a more conventional biomass heat route as a result of the report findings.

3.6.10 Documented experience from Europe 3 4 bears out the observed trends in the UK, i.e. that "bigger is better", and that in the majority of non-industrial applications, the economics of biomass CHP systems are limited in size by the heat market to which they can be connected, although there are obvious opportunities in the more densely populated parts of Scotland for district heating schemes. Above a certain scale however, limitations around fuel supply become apparent, and the physical size and operational characteristics of biomass CHP plants can affect their acceptability in a community setting.

3.6.11 The highly influential 2003 report by the Royal Commission on Environmental Pollution 5 ( RCEP) envisaged the phased deployment of biomass CHP as part of a long term drive towards the deployment of biomass energy technology, anticipating that it would come as part of a second wave of sector development from 2012-2018. The RCEP report felt that this period would see "increasing numbers of small CHP plants installed in hospitals, educational establishments and commercial/industrial establishments", although on the evidence of how the sector has progressed since the publication of this support, it is likely that only the industrial and commercial sectors will embrace this technology within the anticipated timescale.

3.6.12 In a more mature market, mass production of energy systems might bring down capital costs for smaller units, but this does not appear to be imminent in the European marketplace. That said, BEC note that "t his is an area of considerable development and progress is constantly being made."2 In short, there is considerable market potential for biomass CHP, but questions of scale, the experimental nature of much of the conversion technology and most importantly, the capital investment required, makes it an unlikely candidate for landowner or community investment in the short term.

3.6.13 In terms of electricity generation only from biomass, Scottish Government policy is currently focused on encouraging the use of biomass for heat and CHP, and they are currently reviewing support for electricity-only schemes.

3.7.1 According to Government sources 1, there are over 2,344,000 households in Scotland (2009) and this figure is increasing year on year. Almost all dwellings have mains electricity and all have a heat demand. Urban, suburban and rural properties can all benefit from heat pumps. In addition, there are 291,380 private sector businesses operating in Scotland 2. Many commercial and community buildings, such as shops, offices, care homes and schools can be suitable for heat pump installations. Heat pumps work best producing quantities of warm water for use in space heating and for domestic hot water.

3.7.2 Heat pumps generally use mains electricity to harvest heat from an external source, such as water, soil or air. The technology extracts the heat by chilling the source, and concentrating the heat, usually in the form of hot water. A heat pump system relies on the principle that the machinery installed will produce more heat (output) than the system takes to run (input). As heat pumps use the existing electricity grid infrastructure for their operating energy source, they are more accurately classed as energy efficiency technology than renewable energy.

3.7.3 A heat pump which uses one unit of electricity to produce two units of heat is said to have a co-efficient of performance (CoP) of two to one, 2:1. This makes the use of a heat pump to produce heat more attractive than say a direct heating element running off mains electricity where the co-efficient of performance would be 1:1 - where each unit consumed produced a single unit of heat. Whilst the ground, water and air source heat pumps are more numerous, there are also exhaust air heat recovery systems - a heat pump that gathers heat from air within a building before that air is expelled as part of a mechanical ventilation system, and air-to-air heat pumps, which are simpler, smaller units similar to fan heaters, but without the heat storage or the integrated control of more complex systems.

3.7.4 Domestic heat pumps typically have an output of between 5kW and 14kW and commercial heat pump units serving large buildings like schools, office blocks and castles are typically in the range 20 - 110kW. Heat pumps can be combined to work in banks of multiple units of the same or different sizes. Other pumps can have a cooling function as well as a heating function. The electricity consumption of these units is dependent on the CoP at which they operate. This fluctuates with heat demand and climatic conditions, but will always be less than the equivalent rated heating output.

3.7.5 Commercially, heat pumps on a larger scale are more likely to be associated with the recovery of heat from coolant water in industrial processes, or exhaust heat from spaces which need cooling, such as hotel kitchens and bakeries where there is a demand heated water elsewhere in the building or process.

3.7.6 Heat pumps provide a very small proportion of renewable heat in Scotland, with less than a 10% share of the total renewable heat market from an estimated 15 MW of installed of capacity 3. From a technical perspective, the opportunity for a significant rise in the number heat pump installations in Scotland is clear, as they are appropriate for retrofit in a considerable number of existing properties. However, they are most suited to new-build dwellings and other buildings where building regulations have ensured low heat loss.

3.7.7 There are however, a number of market and technical issues which are having an effect on the opportunities for this growth. Firstly, the current market cost per unit of electricity is considerably higher than the cost per unit for mains gas. This means that even with a co-efficient of performance of 2.5:1, a heat pump system may still struggle to compete with the operating costs of an efficient mains gas boiler. Consequently, heat pumps are a more attractive financial opportunity in off-gas areas.

3.7.8 Secondly, the capital cost of an efficient condensing gas (or even oil) boiler is significantly lower than the cost of installing a heat pump system. This is particularly true of ground source heat pump systems, where costly boreholes or trenched collectors are used, or where large accumulator tanks are specified.

3.7.9 Thirdly, there is a need to show that the co-efficient of performance promised by manufacturers is achievable in operation. Whilst improvements in the technology have been made, there are still many reports of heat pump installations which fail to deliver the CoP promised. This can be due to their operation, the physical characteristics or energy inefficiency of the building to which they have been retrofitted, by mis-selling or poor quality installation. Specifically, a heat pump fitted to a new build property with an underfloor heating system can be expected to operate efficiently and at low cost. A heat pump retrofitted to an old property which has not been upgraded to reduce heat loss may struggle to provide the heat needed, with the consequence that input units will be high, especially if the back-up immersion heaters (CoP 1:1) within some heat pump units are activated regularly. Where local climates are more severe, and the heat pump is trying to extract heat from a cold source and deliver heat at high temperature, the CoP will also be compromised. Good Practice Guides have been issued for different types of pumps by the Energy Saving Trust 4 and other trade bodies.

The Outlook

3.7.10 The dominant issue for the heat pump industry in Scotland at present (September 2010) is the unconfirmed Renewable Heat Incentive ( RHI). 5 The RHI, as proposed in the consultation document, will be a payment from government to Ground Source Heat Pump operators of 7p per kilowatt hour for 23 years. Under the draft proposals, Air Source Heat Pump owners would receive 7.5p per kilowatt hour for 18 years.

3.7.11 To be eligible for the RHI, it is proposed that installations must be of approved equipment and undertaken by registered installers to properties with a minimum standard of insulation. The tariff support is intended to compensate operators for the higher-than-gas capital costs of installations, and the current higher-than-gas costs of input electricity. RHI payments at the levels proposed would materially alter the market for heat pumps, as the tariff levels are designed to generate a return for the owner of the technology which will effectively mean a well installed unit will provide a profit over the life of the equipment.

3.7.12 If the RHI becomes a reality, it could make the forms of direct heating, like electric storage heaters or direct gas boilers, much less attractive to new build developers, and will certainly have this effect on the retrofit market. There is still a consideration, however, that in new build housing developments the property developer will build houses to a budget, and the higher capital costs of heat pumps of all types could be a barrier.

3.7.13 The rise in demand for heat pumps of all types, should RHI be confirmed, is likely to result in a market need for trained and accredited heat pump specifiers and installers. There are currently over 200 firms certificated in the UK for heat pumps under the Microgeneration Certification Scheme ( MCS).

3.7.14 The overall demand for electricity may also rise to meet the new heat pump demand, where heat pumps are replacing oil or gas boilers. This has the potential to create capacity issues for local electricity supply networks. Conversely, where heat pumps are replacing electric storage heating or electric immersion heaters, there should be a reduction in the consumption from the mains. The final result on mains electricity consumption is unclear, and the technology does require the constant availability of electricity from the grid.

3.7.15 Specifically considering community groups and landowners, community groups will be in a similar position to private householders and small businesses. If they have an existing building with a heat requirement, then when their existing heating system becomes due for renewal an appraisal of the options will be made. Heat pumps will be applicable in a number of cases, especially where the building is currently thermally efficient, or could be made so. For community new builds, heat pumps are a clear option if the building heat profile demonstrates a relatively constant load, especially if RHI will underwrite the costs and incentivise the decision to go for a heat pump installation. Projects in off-gas areas will see the most financial benefit.

3.7.16 If the RHI was made a certainty, community groups may consider that funding some of the additional costs of a heat pump installation by loan would be acceptable, although even with the RHI, the cost and payback period of a single installation may not be sufficient to make the transaction particularly appealing to a traditional lender. The same is true of their appeal to, for example, a community energy company which is looking to make an investment in energy production. The simple metric is that, the more energy a building uses, the more income there is likely to be from the RHI (subject to the design of the final scheme), and buildings where heat pump technology will find a home will not necessarily generate financially attractive returns.

3.7.17 Landowners have no specific extra benefits as regards this technology, although access to land and/or ponds would permit a householder to install a ground source or water source heat pump. This would be likely to have a higher and more constant coefficient of performance and a longer payment period for RHI. Permitted development rights, where air source heat pumps can be installed without the need for local authority consent, are more likely to apply in less dense housing/built up areas too.

3.7.18 The low capital cost of a heat pump, compared to a wind turbine, coupled with the economics of the payback and the lack of appropriate heat demands on most farms/estates, mean that heat pumps are unlikely to see rapid deployment in these settings as a revenue-generating technology, as landowners will be more likely to focus on the technologies which offer a better return on capital. They will, however, see reasonable uptake as heating sources on a purely invest to save basis in suitable applications. .

3.7.19 In conclusion, where the technology, operation and location are all correct, heat pumps can materially increase the heat delivered from a lower energy input. They rely on a mains electricity supply. Project planning and specification costs are generally done at no cost to the prospective purchaser by prospective installers using software developed by pump manufacturers. The RHI, if implemented, will make heat pumps an obvious space and domestic hot water heating choice for many domestic scale new build properties and retrofit projects. The opportunities for community groups and landowners to do much more than reduce their own heating costs are marginal at best, and it is unlikely that heat pump technology, in its current form at least, will be able to demonstrate the returns on investment required to make non-domestic scale projects viable from an income generation perspective.

3.8.1 Methane is released when organic matter decomposes under oxygen limited conditions. It is produced at land-fill sites and sewage works but almost half (38%) 1 of the annual emissions of methane to the atmosphere are from agricultural production. Methane is the main constituent of natural gas, and as this is transported via a network of pipes around the UK to domestic and industrial premises for heat and power production. Methane captured from other sources could, in the future, be fed into the gas grid.

3.8.2 This would have the twin benefits of reducing the consumption of natural gas and reducing methane release. Combustion of methane produces energy, but also carbon dioxide and water. It is now well known that methane is about 21 times 2 more powerful as a greenhouse gas than carbon dioxide, so the earth's atmosphere will benefit if methane emissions are reduced. The challenge is to capture and use methane produced from decomposition on site. The easiest way to use methane is to burn it, reducing the reliance on fossil fuels. However there needs to be a local, continuous, need for the heat produced, within about 100 - 200m, for this to be economically worthwhile.

3.8.3 If there is a mains gas supply, it may in future be worth considering cleaning the gas and adding it into the grid, but this is not yet a viable option. Similarly, methane could be used as a vehicle fuel, but until the infrastructure is set up to facilitate this, and the road fuel tax system is adjusted, this will remain an option for the future. The alternative is to burn the methane in gas engines to produce electricity. Power is in most cases more expensive than heat, and where there is a local demand for power or, given an acceptable electrical grid connection for export, it may be easier to export than find a demand for heat.

3.8.4 Whilst there are good examples of methane being trapped in landfill sites and AD technology has been installed in sewage works for many years 3, the development of systems appropriate for farms in the UK has been slow. Current government incentives have increased interest, but it is unclear whether this will be sufficient to create real growth. There are three main types of feedstock 4 that can be used in AD plants on farms : organic waste imported to the farm for "disposal", usually paid for by the producer, farm waste disposal and organic matter grown locally for energy production.

3.8.5 The benefit of disposing of organic wastes on farms is that the digestate can be spread on farmland fertilising the next crop and reducing the need for inorganic fertiliser. The waste producer gets a route of disposal avoiding Landfill Tax, and the biogas system operator is paid to dispose of high gas yielding feedstock, producing heat and power which can be sold. Clearly, controls are needed to ensure that the quality of the material digested is sufficiently high that the agricultural land will not be harmed, but if these are effective, the potential benefit is huge. The Waste Resources Action Programme ( WRAP) report 5 that 8.3 million tonnes of food waste is sent to landfill each year. Returning this to the land following digestion and energy extraction, would reverse the loss of organic matter and replace fossil fuel derived fertilisers.

The Outlook

3.8.6 Until recently, food waste, with its accompanying gate fee, was seen as essential for the economic viability of AD systems. However this has extra costs, as the waste has to be pasteurised, and the plant is vulnerable to external factors, for example if the supply of waste is removed due to the producer's business failing, or if another AD plant starts in the area. Farmers do not need to compete with Local Authorities to dispose of municipal waste, and there will be many cases where a mutually beneficial arrangement can be agreed.

3.8.7 Additionally, there are around 5 million pigs 6 and 10 million cattle 7 in the UK, and they each produce a quantity of manure that has the potential to yield a biogas containing about 55% methane. If it were possible to extract the methane from all of this manure, the potential power produced would equate to about half that of a conventional power station. However, as the manure is often difficult to collect, very expensive to transport, and produced in a large number of disparate facilities, this is unlikely to be practical.

3.8.8 Using an on-farm AD plant to digest manures is particularly attractive, as the nutrient value is unaffected, meaning that the same fertiliser value will be achieved from the digestate as from the fresh manure when they are spread on the land. The amount of methane obtained from manures is relatively low, as the material has already been digested. This means that it is difficult to find a system that will be viable; that is one that has a sufficiently low capital cost to achieve a reasonable payback period. The option of installing a less automated system has been suggested in the past, but found to be un-workable due to the technical input needed to keep such a system operating efficiently. Periodically, lower cost systems are advertised, but to date there are no small-scale systems that are proven in commercial operation available in the market. It is likely that a biogas plant will have to have an output of around 300-500 KWe, but in general, the larger the system, the more economic it will be.

3.8.9 There is a well developed biogas industry elsewhere in Europe, encouraged by government subsidy, and thousands of biogas plants have been installed on farms to provide an alternative income for rural businesses. The Feed-in Tariffs 8 recently introduced in the UK have given price stability for the next 20 years, and show progress towards the levels of support available in countries like Germany. This has led to increased interest in biogas systems in the UK, and the number of plants installed increasing, especially in England. Extra grant support has helped this in some cases. There are a number of other factors which may make a difference between the economic viability of plants in UK with those in Germany:

Lower capital costs in Germany;

Better support and maintenance networks;

Widespread availability of high gas yielding feedstock, such as maize;

Lower cost of feedstock;

Higher dry matter content of feedstocks;

Higher likelihood that waste heat will be used;

3.8.10 The gas output of energy crops is considerably higher than for manures, for example, the gas output of maize is about 10 times that of cattle slurry. This makes a system more viable, but only if the feedstock can be produced sufficiently cheaply. Without an increase in the FiT for this type of biogas system, very careful selection of feedstocks and full analysis of cost is needed before viability can be assured. If the FiT were to be increased to help offset the cost of feedstock, especially in Northern areas where maize does not grow well, the potential for this industry would very rapidly increase. Once there are more plants running, confidence will grow, installation costs will fall and capital cost may reduce as economies of scale kick-in.

3.8.11 In conclusion :

The biogas industry has been slow to start in the UK but is getting going, especially in the south of the UK;

The system cost is still high meaning that larger plants are more likely to be viable;

Extra grants, secure source of waste foodstuff or low cost farm energy crops for use as a feedstock are needed to pay back capital costs efficiently;

Alternatively, an increase in FiT levels, or income from the use of waste heat, ideally supported by Renewable Heat Incentive payment, is needed to fully stimulate the market;

There is considerable future potential for using methane produced on farm as a replacement for natural gas, or as a vehicle fuel, when infrastructure has been set up to clean and handle the gas supplied from AD plants.